The present invention relates generally to the oil and gas industry: in particular to oil well production utilizing reciprocating pumps and the servicing of same.
Oil wells are produced using a variety of methods ranging from self-production, where the formation pressure is high enough to cause the oil to flow up the wellbore, to various forms of artificial lift, where the formation pressure is insufficient and cannot lift the hydrocarbon fluid up the wellbore. The most common artificial form used in the oil industry is the reciprocating pump.
The standard industry reciprocating pump consists of a prime mover that is positioned at the surface, and a pumping barrel that is positioned within the production tubing at or near the bottom of the wellbore. The wellbore is lined with steel pipe called casing.
The production tubing is concentric within the casing and is the conduit through which produced fluids are sent to the surface. The area between the production tubing and the casing (wellbore) is called the annulus. The production tubing is generally suspended from the surface and xe2x80x9crestsxe2x80x9d against the casing forming a seal at the surface. The steel casing has a series of holes or perforations punched in the casing where the producing formation is found, that allow the formation fluid to enter the annulus.
The production tubing has a xe2x80x9cseating nipplexe2x80x9d at the formation end of the tubing into which the pump will seat. The tubing may be terminated in a rounded end with a series of perforations that act as a course filter and allow the formation fluid to enter the production tubing. The seating nipple has a reduced inside diameter when compared to the tubing that forms a hold-down into which the pump barrel locks or is held-down. The barrel is locked into place within the production tubing so that a seal is formed between the pump and the production tubing. This seal keeps the produced fluid from re-entering the formation.
There are two ways by which the pump at the end of the production tubing is driven (reciprocated). The first uses the industry standard sucker rods, and the second uses a new technique that employs a wire cable. Both the cable and the sucker rod string terminate at the pump and at the prime mover. A cable driven pump will employ the same (or similar) pull rod at the downhole end. Thus, the sucker rod string in a sucker rod driven pump and the cable in a cable driven pump terminate in the pull rod.
After a period of time, the downhole pump must be serviced, and the cable or sucker rod string is employed to lift the pump up and out of the well. The pump is pulled up to the surface within the production tubing. A certain amount of force is required to xe2x80x9cpopxe2x80x9d the pump loose from the hold-down at the bottom of the production tubing.
Very often the force to xe2x80x9cpopxe2x80x9d the pump loose is excessive and is caused by xe2x80x9cflower sandxe2x80x9d buildup around and about the pump at the hold-down. Flower sand is entrained in the produced fluid and tends to precipitate from the fluid as it passes up the production tubing. The sand then falls to the bottom of the tubing and xe2x80x9cpacksxe2x80x9d around the hold-down thereby substantially increasing the force required to xe2x80x9cpopxe2x80x9d the pump loose from the hold-down.
Further more because there are series of ball and check valves within the pump, the initial force required to xe2x80x9cpopxe2x80x9d the pump loose must also pull against the hydrostatic head contained within the production tubing which thereby increases the required unseating force. As the depth of the well increases, the weight of the produced fluid increases: essentially, the weight of produced fluid is related to the hydrostatic head contained within the production tubing. As soon as the pump pops loose the hydrostatic head will reduce because the fluid in the production tubing will U-tube within the annulus and tubing.
There have been instances when the sucker rod string breaks, due to the high force required to xe2x80x9cpopxe2x80x9d the pump loose, thus leaving the pump in the tubing. At this point, the well operator must pull the production tubing to retrieve the pump: an expensive operation. In the case of the wire cable driven pump, the wire cable is often limited in pulling force, and the tubing would have to be pulled.
Among some of the prior art attempting to solve the problem caused by sand buildup and hydrostatic head are: Hall (U.S. Pat. Nos. 5,018,581 and 4,103,739), Hix (U.S. Pat. No. 3,994,338), Howe (U.S. Pat. No. 3,150,605), Owen (U.S. Pat. No. 4,909,326), Sonderberg (U.S. Pat. No. 4,645,007) and Sutliff et al. (U.S. Pat. No. 4,273,520. Hall envisions an auxiliary valve-like device that is placed at some point (mid) in the pump barrel as the barrel is being made up. This valve opens during withdrawal of the pump if the pulling force exceeds a predetermined force caused by sand buildup. If the device does not open, then it is assumed there is no sand buildup and the device may be re-inserted into the wellbore.
Hix describes a frangible rupture disk that is placed between the standing valve and the hold down in a barrel pump assembly. The rupture disk is activated by increasing the pressure in the standing column of produced fluid; thus, some sort of pumping device is required at the surface. The device also incorporates a left hand thread that allows the pump to be unscrewed if the rupture disk fails to rupture. This is a one shot device.
Howe illustrates a complex ball and seat device that is placed at the pump head and drains the tubing fluid above and around the pump whenever the pump is raised out of the tubing. It does not release the hydrostatic head in the tubing.
Owen portrays a tubing unloader that is placed in the tubing itself. As the tubing is pulled upward the unloader opens and allows the entrapped fluid to drain back into the annulus.
Sonderberg also describes a tubing unloader that is placed in the tubing like the device of Owens. However, the Sonderberg device uses an increase in fluid pressure to open the device. Again this implies some sort of pump source at the surface. Finally, Sutliff et al. disclose a deep well pump that incorporates a drain valve that allows the pump to drain within the tubing so that the pump is basically pulled dry from the well.
The industry has attempted to solve the flower sand problem by using a bottom discharge valve mounted below the pump, but above the lower check valve (stationary valve), that allows back flow of produced fluid, thereby causing a swirl that hopefully picks up the sand about the hold-down reducing the force required to xe2x80x9cpopxe2x80x9d the pump loose. The valve which is really a second check valve that, on the downstroke, allows flow of produced fluid from the pump barrel into the tubing (Note the valve is spring loaded so that downward force is required to force the produced fluid backwards into the tubing.) The by-passed flow causes a swirl around the bottom section of the pump and up into the tubing. The device helps but, because it is located away from the hold-down, it is somewhat inefficient when washing sand. The force required to push the fluid through the bottom discharge valve is supplied by the weight of the sucker rod string (coupled through the pull rod). The required force (xe2x80x9cweightxe2x80x9d) is unavailable in a cable driven pump. (xe2x80x9cOne cannot push on a rope.xe2x80x9d) The industry has not resolved the hydrostatic head problem.
Thus, there remains a need for a device that will wash the flower sand buildup from about the hold-down within the production tubing and/or reduce hydrostatic head, thereby reducing the force required to xe2x80x9cpopxe2x80x9d a pump loose for servicing. The need is even higher for cable driven pumps.
The prototype device is about 12 inches long, consists of three major parts and would be run between the ball and seat and the hold down (stinger) prior to being placed in the wellbore. The first part is the outer barrel that attaches to a standard hold-down stinger. The second part is a hollow moving piston within the barrel. The third part is header that attaches to the piston and to the bottom of the pump barrel immediately below the ball and seat. Produced fluid normally flows from the hold-down stinger, through the hollow piston, through the header, and into the ball and seat assembly associated with the pump.
The piston has a set of apertures, called dump aperture(s) or dump port(s), and a series of seal O-rings. The O-rings and apertures remain within the barrel until activated by forces applied from the surface. The dump port(s), if exposed from within the barrel, will allow fluid to flow from the hollow aperture.
The device has three xe2x80x9cpositions.xe2x80x9d These positions are the entry position, the cocked closed or safety position and the dump position. The entry position is the initial position and is kept in this position by an entry shear pin or a set of entry shear pins. In the entry position, the header is approximately xc2xd-inch above the barrel. At the same time the xe2x80x9cdumpxe2x80x9d port(s) remain(s) xe2x80x9clockedxe2x80x9d within the barrel. No fluid can pass from within the hollow piston and the outside of the barrel. Produced fluid only flows from the formation into the pump and onto the surface.
Allow some time to pass and require that the pump be served. The operator allows the reciprocating system to drive the device downwards toward the bottom of the well. This action shears the xe2x80x9centryxe2x80x9d shear pin(s) and allows the header to come into contact with the barrel. The device is now xe2x80x9ccockedxe2x80x9d in that it may be opened. The operator then draws up on the reciprocating system causing the piston to move upwards within the barrel towards the top of the device. Additional upward force is required to shear the xe2x80x9csafety-pin(s)xe2x80x9d within the barrel. This then allows the piston to move further upward exposing the xe2x80x9cdump port(s)xe2x80x9d that allow(s) for reverse flow. The reverse flow will allow the hydrostatic head to dissipate into the annulus, and, if required, wash flower sand from around the hold-down; thereby, reducing the total pull required to xe2x80x9cpopxe2x80x9d the pump loose and withdraw it from the well.